This invention relates to the field of well logging. More specifically, the invention relates to a novel apparatus and techniques for eliminating data acquisition errors inherent in electromagnetic propagation wave devices. The invention also relates to an apparatus and method for measuring the resistivity of geologic formations surrounding a borehole during well logging and logging while drilling operations.
Formation resistivity is commonly used to evaluate geologic formations surrounding a borehole. Formation resistivity indicates the presence of hydrocarbons in the geologic formations. Porous formations having high resistivity generally indicate that they are predominantly saturated with hydrocarbons, while porous formations with low resistivity indicate that such formations are predominantly saturated with water.
Devices have been previously developed for measuring formation resistivity. Many of these devices measure formation resistivity by measuring the properties of propagating electromagnetic waves. For example, FIG. 1 shows an early generation, uncompensated propagation wave resistivity tool comprising one transmitter and two receivers for measuring the properties of an electromagnetic wave over two propagation paths. Property P11 represents an electromagnetic propagation property for the propagation path from transmitter (Tx) to a first receiver (Rx1), and P12 represents the same electromagnetic propagation property as used for P11 but for the propagation path from the transmitter to a second receiver (Rx2). Typically, the propagation properties measured are attenuation and phase. A differential measurement (M) is formed by taking the difference between P12 and P11. This difference allows any errors related to the transmitter elements of the system to be removed from the final measurement (M). The measurement (M) is then converted to formation resistivity (R) via function (f) which provides the relationship between the differential propagation property (M) and the resistivity of the surrounding formation.
FIG. 2 illustrates another propagation wave resistivity tool described in U.S. Pat. No. 4,949,045 to Clark et al. (1990) and in U.S. Pat. No. 4,968,940 to Clark et al. (1990). This tool provided improved measurement accuracy and reduced sensitivity to the effects of borehole irregularities when compared to the “uncompensated” tool shown in FIG. 1. Such tool comprised two transmitters and a receiver pair located between the two transmitters and is known as a borehole compensated tool. MU represents the differential measurement for the upward propagating electromagnetic wave from transmitter (Tx1) and MD represents the differential measurement for the downward propagating electromagnetic wave from transmitter (Tx2). A borehole compensated measurement MBHC can be calculated by averaging the upward propagating measurement, MU, and the downward propagating measurement, MD. The formation resistivity is determined in a fashion similar to the uncompensated tool by converting propagation property (MBHC) to resistivity with function (f). By averaging the measurements from the upward and downward propagating electromagnetic waves, the effects of borehole rugosity on the measured formation resistivity can be reduced. This average also removes errors corresponding to the two receiver elements of the system, Rx1 and Rx2. Like the uncompensated device, the borehole compensated device also eliminates the errors related to the transmitting elements of the system by using differential receiver measurements, MU and MD.
Although borehole compensated tools provide a more accurate measurement of formation resistivity than conventional uncompensated tools, such technique requires a tool approximately twice as long as an uncompensated tool. Tool length for an uncompensated tool with a single radial depth of investigation is directly related to the spacings between the transmitter and receiver pair. Longer spacings between the transmitter and receiver pair provide greater depth of investigation than shorter spacing and require a longer tool body accordingly. The tool length for a borehole compensated tool as described in patents '045 and '940 with an equivalent radial depth of investigation as an uncompensated tool will be approximately twice as long because of the requirement of both upper and lower transmitter elements.
Another compensated tool was described in U.S. Pat. No. 5,594,343 to Clark et al. (1997) wherein the transmitters were asymmetrically located on both sides of a receiver pair. Similar to the '045 and '940 patents previously described, such tool also required placement of at least one transmitter on each side of the receiver pair and also required a long tool body.
The compensated tools described above require a long tool body in the borehole to correctly position the transmitters and receivers. Long well tools not only require additional material and cost more to manufacture but they are more likely to bind or stick in narrow or deviated boreholes. This problem is particularly acute in multilateral wellbores having a reduced entry radius and in highly deviated wellbores. Accordingly, a need exists for an improved system with reduced cost that is also capable of facilitating tool movement within a wellbore while gathering useful information regarding geologic formation characteristics such as resistivity and other geologic formation indicators.